In the oil-exploring industry, gas and liquid mixed fluids comprising liquid phase and gas phase are usually explored from oil wells, and the fluids are customarily called as “wet gas” in the art. The wet gas belongs to a multiphase flow in nature, that is, to be a mixed fluid of gas phase and liquid phase. Said gas phase includes, for example, oil field gas or any gases which are non-condensable at room temperature, wherein the oil field gas is generally relatively light alkanes, such as methane, ethane, propane, butane and the like. Said liquid phase may include: an oil phase, e.g., crude oil per se, and other liquid additives which are dissolved in crude oil during the exploration of crude oil; and a water phase, e.g., formation water, water which is injected into oil wells during the exploration, and other liquid additives which are dissolved in the water phase. The liquid volume flowrates and gas volume flowrates of gas and liquid mixed fluids explored from oil wells, which are real-time and accurately measured, are necessary basic data for production management and production optimization.
A first method relating to a device for measuring gas and liquid volume flowrate in a multiphase flow has the following working mechanisms: a gas and liquid mixed fluid is separated into a gas phase and a liquid phase via a separator. The separator generally achieves the gas and liquid separation by the means of the gravity force. Alternatively, the gas and liquid separation is achieved via a cyclone separator. Then, the volume flowrates of the gas phase and liquid phase can be respectively metered. However, because the separator and relevant instillations affiliated thereto weigh to be decadal tons, occupy a space having an area of hundreds square meters, and have many controlling links, maintenances and managements for the separator are complex, which is disadvantageous to automation of the management to production procedure, in particular, disadvantageous to the use in oil fields in desert and ocean. Furthermore, the method in which the liquid phase and the gas phase are separated from each other and then their flows are measured is not a real-time on-line measuring method, there is a hysteresis in the measurement.
A second method for online measurement of gas flowrate and liquid flowrate of wet gas is described as follows: a single phase meter is arranged horizontally along production pipelines for wet gas, and the wet gas is measured as a single phase. Since no multiphase meter is used, the liquid amount or an approximate value thereof should be known beforehand by other routes. Metering result of the single phase is deemed as the gas amount, while usually, the value is falsely high, and thus it should be corrected. A commonly-used correction method in the art is the interactive calculation based on the Lockhard-Martinelli parameter of gas phase and liquid phase, and a main representative of the calculation method is the ISO wet gas model, for example, please see ISO/TR 11583:2012, with the English title “Measurement of wet gas flow by means of differential pressure devices inserted in circular cross-section conduits”, where all the corrections are directed to the gas amount. However, the method has three primary disadvantages: 1. there is on explicit dynamic mechanism; 2. only the gas amount is corrected, and no calculation and correction to the calculation of the liquid phase; and 3. the applicable scope of the method is only limited to a narrow range of the gas content of a fluid having a very high gas content.
A third method is concerned with a total flowrate metering device and phase fraction meter horizontally arranged along the production pipeline of wet gas, which can measure the total volume flowrate Qt and the gas linear phase fraction αg along a certain radial direction of the horizontal pipe, respectively, and the following equations can be calculated: Qg=Qt×αg; Qt=Qt×(1−αg), wherein Qt is the total volume flowrate; Qg is the gas volume flowrate; Ql is the liquid volume flowrate; and αg is the gas linear phase fraction.
In the method, wet gas in the horizontal pipeline is generally assumed to be a mist fluid, that is, in a state wherein the liquid phase in the horizontal pipeline is uniformly dispersed in the gas phase in a form of droplets, and there is no slip difference between the liquid phase and the gas phase. Furthermore, the phase fraction meter in the method is generally arranged at a certain radial position of the horizontal pipe, and the measured gas phase fraction is the gas linear phase fraction αg at the radical position. Since the above “homogenous phase” and “no slip difference” are hypothetically present, the measured gas linear phase fraction αg is equivalent to the gas area phase fraction αsg and the gas volume phase fraction GVF. The methods assumes that the wet gas in the horizontal pipe is a homogenous mist fluid and there is no slip difference between gas phase and liquid phase, which is not in line with the actual situation of the wet gas flow. In the horizontal pipe, due to impacts of gravity, systemic pressure and temperature, and the amount of the moisture in the wet gas, the wet gas is not an ideal homogenous state in the horizontal pipeline, and thus there is the error when using the gas linear phase fraction αg along the radial direction of the horizontal pipe to replace the gas volume phase fraction GVF, and the impacts of the above factors on the measuring precision of the liquid phase are even more obvious. In the wet gas, GVF is a number close to 1, and minor variances in the GVF value will lead to a great relative error of the LVF, thereby to result in a great measuring error of the liquid phase flowrate. Thus, in the method, the measuring precision of the liquid phase is usually poor.
In a fourth method, the above measurements are carried out in a vertical pipeline, so as to avoid the deviation from the above “mist flow” hypothesis caused by the deposition of liquid phase on the bottom of the pipeline, wherein, all pipelines to be measured are arranged vertically. However, production pipelines of wet gas in oil field are usually horizontal, and thus the above measurements can be carried out only when the direction of the pipeline are changed from a horizontal orientation to a vertical direction. Thus, in the method, the direction of the pipeline should be changed and a transition pipeline should be arranged for stabilizing the flow pattern, so that the measurement device occupies a large space, which is disadvantageous to the arrangement of an oil and gas platform at sea which requires a high layout compactness.
Hence, there is a need in the art for a device and method which can online measuring gas flowrate and liquid flowrate of wet gas in a horizontal pipeline, which is not in need of changing the flowing direction of fluid, so that the measurement can be carried out by using a measuring device having short tube structure, and spaces occupied by the measuring device can be greatly reduced and the arrangement operations are simplified, while achieving a measuring precisions as high as possible.